boiler mact compliance - neundorfer

Boiler MACT Compliance: You Might be Closer Than You ThinkInsights learned from working with power utilities andindustrial facilities on compliance projects

Introduction Neundorfer, Inc., Storm Technologies and United Dynamics Corporation are working

together to help utilities and industrial companies develop pollution control and energy effi ciency strategies. In this paper, we discuss factors in each area of the process that aff ect the existence, formation or capture of pollutants regulated by the Boiler MACT rules.

Th ese insights touch on many sub-topics, including: • Th e concept of control, infl uence and react as it relates to MACT compliance. • How fuel preparation and combustion impact MACT pollutants. • How issues with heat transfer aff ect the formation of MACT pollutants in the boiler. • Air in-leakage and how this impacts MACT pollutants. • Eff ective ways of capturing MACT pollutants on the back end of the plant.

Control, Infl uence, React Our objective in this paper is fi rst to touch on what we can

control, what we can infl uence, and what we need to react to in relation to pollutants regulated by MACT. Envision these as a series of spheres; what we control is very small, in the center. What we can infl uence, but not control, is a larger sphere. What we have to react to, but cannot control or infl uence, is much larger.

When creating strategies, such as for compliance, we are faced with this scenario and must understand what is within our control, what we infl uence, and what we are reacting to. We will start by sharing some of the things learned so far from working with customers on MACT compliance projects.

Boiler MACT ComplianceAuthors: Steve Ostanek, President, Neundorfer, Inc.; Jeremy Timmons, Chemical Engineer, Neundorfer, Inc.;Richard Storm, CEO, Storm Technologies; John Cavote, Chairman of the Board, United Dynamics CorporationEdited by: Mae Kowalke, Manager of Stories, Neundorfer, Inc.

June, 2011

Figure 1: Spheres of Control,

Infl uence and React

Boiler MACT Compliance continued

What We Have Learned About MACT We are currently involved in a few MACT compliance planning eff orts. One of the initial

steps in the planning process was to design and execute a baseline testing program that produces the information necessary for making future decisions. In reviewing some of the initial baseline results, most of the boilers were meeting or within reach of compliance on many of the MACT pollutants.

Figure 2 displays a summary of current MACT pollutant emissions (carbon monoxide, dioxins/furans, hydrochloric acid, mercury and particulate) from 11 of the boilers we are currently evaluating. Th e colors indicate each boiler’s level of compliance with each pollutant. Green means that they are well within compliance. Yellow indicates that the emissions levels are below MACT limits with little margin. Orange indicates that current emissions levels exceed MACT limits.

Th is group of boilers has a serious problem with CO and dioxins and furans. About half of the boilers are near or above MACT mercury limits. Th e same can be said for particulates.

Note that boilers 4 and 5 easily passed all MACT emissions tests. We believe that some of the answers for improving the other boilers can be extracted from further analysis of #4 and #5; it seems likely that their MACT pollutant levels are partly a result of superior combustion and optimal fl ue gas temperatures.

For the other nine boilers, we would fi rst recommend a program to improve combustion. Th e goal of this program is to reduce CO and D&F formation, and also improve particulate and mercury emissions by reducing treated gas volume.

If mercury is still an issue after these front-end improvements are made, it might be necessary to add some sorbent and make sure the precipitator is operationally good. Likely, most of these boilers can be brought into compliance without spending a dime on particulate or mercury removal equipment.

Figure 2: MACT Case Study


Th e next step might be to look into any other process improvements that could reduce treated gas volume. Th ese include improving thermal effi ciency, reducing air in-leakage, and reducing exit temperatures to a reasonable level. In extreme cases, as much as 1,000 BTUs per kilowatt hour heat rate can be gained through such a program. Th is translates to 20-30 percent reduction in particulate emissions. After completing this program, we might recommend re-testing the MACT pollutants.

Before considering any add-on controls, boiler operators should fi rst invest in a baseline testing and optimization program. Baseline testing is more than just a stack test. It is an integrated eff ort that seeks to understand the whole system and the stack test is just part of it. Th e goal is to combine combustion systems testing (primary/secondary/over-fi re air measurements, O2 rise from furnace to the stack, etc.) with reliability and environmental considerations. Th orough testing and optimization for a typical 500 megawatt boiler costs around $200,000. Ideally, such testing should be performed before and after each major outage so maintenance people have data they need to make cost-eff ective, meaningful and results-oriented corrections or adjustments.

Such a program requires looking at the right data and understanding how it is all interconnected. We have been involved with many programs where the user thinks they have the right data, but it does not correlate with anything and we have to start over. Bad data usually leads to bad decisions.

Fuel Preparation and Combustion It is also necessary to understand

how each of the MACT pollutants is created, infl uenced or controlled in the fuel preparation part of the system and during combustion.

First, consider particulate matter. If coal is not burned completely, carbon becomes part of the particulate matter that has to be treated. Th at is why coal fl y ash is sometimes called “refuse” by boiler effi ciency engineers. Th e refuse is both ash and unburned carbon. Coal fi neness has a huge impact on particulate matter quantity and properties. High levels of carbon in ash causes problems for electrostatic precipitators.

Poor fuel fi neness has at least three adverse eff ects on combustion. First, it aff ects carbon in ash. Secondly, it impacts fl ame carryover into the convection pass of the boiler, which can result in superheater slagging and fouling, draft losses, and other problems. Finally, because of delayed combustion and resulting fl ame quenching, poor fuel fi neness causes carbon monoxide


production. CO can be minimized by optimum particle size and fuel distribution. Th ese are all fundamentals of good combustion.

One characteristic, like fuel fi neness, can have multiple eff ects on the process, which then can have multiple eff ects on emissions.

Best Practices for Optimizing Combustion Optimizing inputs to the furnace is important for fi ve reasons.

First, most plants do not have good fi neness on a day-to-day basis. When a push comes to a shove, operations will generally sacrifi ce fi neness for pulverizer throughput. More fuel into the furnace can create more steam production to produce more megawatts even if it is done ineffi ciently. Often, the plant focus is on power production not excellence in combustion.

Second, when fi neness deteriorates, so does fuel balance. Conversely, when fuel fi neness is very good, so usually is fuel distribution. Good fi neness by our defi nition is about 75 percent or better passing a 200 mesh screen and only one or two tenths of a percent on a 50 mesh screen. So, when fi neness is very good, usually so is fuel distribution balanced to the individual burners. Th e idea here is to treat each burner like a cylinder in an internal combustion engine. We like to have in the range of plus or minus 10 percent to each burner. Poor fi neness can result in fuel distributions of ±25 percent and even worse.

Th ird, the furnace residence time for complete combustion is only one or two seconds, at most. We have seen some boilers were residence time is as low as a quarter second from the top burners to the superheater. From this, it is easy to understand the importance of getting the inputs to the burner belt optimized.

Fourth, CO must be combusted in the furnace. Achieving low CO at the furnace exit is the start of reducing the formation of dioxins and furans. Excellence in furnace combustion can be measured by using a water cooled HVT probe and extracting furnace fl ue gases to run through an analyzer. If the furnace is oxidizing, say, three percent excess oxygen at all points, and the fi neness is good, then chances are the CO levels will be very low.

Figure 3. How Fineness Aff ects Fuel Distribution

Microprocessor,gravimetric, load cellSTOCK® coal feeder

Air/Fuel ratio

Fuel line balance

Throat velocity mustbe optimum toprevent coal rejects

Mechanical condition

Primary airflowmeasurement and control

Combustion airflowmeasurement & control

lean air balancing with ± 2%

factor calibration ± 3%

with balance of ± 5%

testing by air/fuel ratio sampling & ensuring optimum fineness level is achieved

The Six Step Approach to Fuel Line Balancing

Figure 4: Solid Fuel Injection System

Relationship Between Fuel Fineness and Distribution

Ave

rage

% P

assi

ng 2

00 M

esh

Maximum Fuel Imbalance From Mean (%)

85

80

75

70

65

605 10 15 20 25 30 35 40 45 50


Finally, temperature is a key factor of effi cient combustion impacted by optimized inputs. In a non-optimized furnace, we have seen gas temperatures at the superheater being 1,000 degrees higher than design—hot enough to melt platinum-rhodium and stainless steel radiation shields. Platinum melts around 3,200 .̊ If fl ames are being quenched in the superheater, CO will be off -scale for many of our analyzers. Getting the inputs right is a huge opportunity on almost all the boilers we have been involved with.

At Storm, based on our long experience in this area, we have developed our pretty well-known 13 Essentials

of Optimum Combustion. Th ese are a great start.

Nine of the 13 essentials are pulverizer, primary air, fuel line and classifi er related. Fuel fi neness, primary airfl ow measurement and control, classifi er tuning, secondary airfl ow, and over-fi re airfl ow measurements and control remain vitally important. Proper airfl ow proportioning during load changes is a particular challenge with swinging loads, such as where intermittent wind mills supply power to the grid.

Heat Transfer In this section, we consider how

slagging, soot blowing and other issues with heat transfer aff ect the formation of MACT pollutants in the boiler. We also touch on infl uences that come into play in the boiler, aff ecting the diffi culty of separating these pollutants when reacting to them downstream.

Figure 5: Combusting Coal - Time Requirements

Figure 6: 13 Essentials of Optimum Combustion for Low NOx Burners

1. Furnace exit must be oxidizing, preferably 3%. 2. Fuel lines balanced to each burner by “Clean Air”test ± 2% or better. 3. Fuel lines balanced by “Dirty Air” test, using a Dirty Air Velocity Probe, ± 5% or better. 4. Fuel lines balanced in fuel flow to ± 10% or better. 5. Fuel line fineness shall be 75% or more passing a 200 mesh screen. 50 mesh particles shall be less than 0.1%. 6. Primary airflow shall be accurately measured and controlled to ± 3% accuracy. 7. Overfire air shall be accurately measured and controlled to ± 3% accuracy. 8. Primary air/fuel ratio shall be accurately controlled when above the minimum. 9. Fuel line minimum velocities shall be 3,300 fpm.10. Mechanical tolerances of burners and dampers shall be ± 1/4” or better.11. Secondary air distribution to burners should be withing ± 5% to ± 10%.12. Fuel feed to the pulverizers should be smooth during load changes and measured and controlled as accurately as possible. Load cell equipped gravimetric feeders are preferred.13. Fuel feed quality and size should be consistent. Consistent raw coal sizing of feed to pulverizers is a good start.

65%65%

33%%

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Heating & MinorDevolatilization

Ignition

MajorDevolatilization

Burning of Carbon

Times vary with different coalsand firing conditions, but thecombustion of carbon alwaysrequires the most time.

Flame quench zone

Point atwhich

combustionshould becomplete

Residence timeof 1-2 seconds

0.000 0.200 0.400 0.600 0.800 1.00

Friable fl y ash

Hard red slag

White deposit

Hard black scale (Fe3O4)

Figure 8: Fuel and Coal Ash Corrosion


Historically, the boiler reliability group at UDC has not spent much time thinking about environmental compliance issues. It was not until the development of our alliance with Storm and Neundorfer that our eyes were opened to all aspects of plant operation, from the coal pile to the stack outlet. We soon discovered that by understanding the other processes we could signifi cantly improve our own specifi c scope of concern—“Th e Pressure Parts.”

Slagging is a great example of something that ranks near the top of the list when it comes to boiler tube leak preventative maintenance, and which also impacts and is impacted by other processes. Removal of slag is one of UDC’s bread-and-butter maintenance programs. We do sandblast cleaning and take extensive tube thickness readings utilizing ultrasonic instruments. Our goal is to eliminate boiler tube leaks. After sandblasting and thickness testing, we replace or repair tubes to restore original minimum wall thickness, and also adjust or repair soot blowing devices. What is typically left out of our equation, though, is a joint eff ort involving combustion performance and environmental people.

If the combustion inputs are correct, then the formation of slag and ash buildup is reduced, and subsequently the need to spend time removing slag is also reduced. Ultimately, there are multiple benefi ts achieved by optimizing combustion. In this scenario, our responsibility in the boiler reliability group is to supply meaningful information in the form of quantity and specifi c locations of ash and slag to the combustion folks so they can take proactive measures that get at the root causes of slagging.

Reducing slag not only helps with the overall tube life and reduction of forced outages caused by its removal, but also helps the distribution of heat evenly across all pressure parts. Slagging causes plugging and poorly distributed heat transfer. Some tubes are much hotter than design and some tubes are much cooler. Failures always occur at the extremes, not the average.

Th is imbalance creates long-term overheat conditions in portions of a component. However, when we replace pressure parts, it is normal practice to replace all tubes because of economies of scale. Many good tubes are scrapped and a lot of money is wasted by these premature replacements.

What we really want to do is prevent tube failures from happening in the fi rst place, and that requires controlling slagging and the related problems of corrosion. Coal and fuel ash corrosion is temperature-dependent—the right conditions must be present for corrosive chemicals to form. Plugging makes it harder to

Figure 7: Waterwall Sandblasting and Pad Welding

PRB-fi red boiler waterwall section next to active soot blower. Part of tube (arrow) was cleaned bysandblasting.

Pad-welded tubes (to restore thickness)


predict where this corrosion will appear, and makes managing the problem far more complex and much more expensive than it would be otherwise.

Th e erosion, or thinning, rate of boiler tubing increases to the square of velocity of the combustion gases. Slagging causes high velocity in some zones and low velocity in others. Th e result is high thinning in some locales and less thinning in others.

When the boiler is not fouled due to slag and ash it breathes easier or more predictably. Certain locations of the physical design of a boiler were intended to provide changes in pressure drop, resulting in drop out of larger slag and ash. Th ese locations include the hopper bottom, the slag fence at the inlet to the back pass, and a turn and drop out hopper at the economizer outlet. Slagging in many cases reduces the eff ectiveness of these design elements, causing high erosion rates and higher ash loading of the air heater and environmental collection equipment.

Th e point here is that many factors related to effi ciency and compliance are inter-related. For example, with better control over chemistry in the fi rewall area we get a better shot at reducing corrosion and long-term overheat caused by poor gas fl ow and temperature distribution. Th is is why our three companies are working together with a holistic approach to optimization and compliance. Our goal is to look beyond the things where normal return on investment is considered. Many benefi ts come out of the woodwork when we go back to the basics.

Figure 9: Tubing Exfoliation Caused by Slagging/Plugging and Poor Gas Distribution

Figure 10: Eff ect of Ash Plugging on Gas Flow

Figure 11: Boiler Design and Slag Removal

Slagging and plugging cause poor gas distribution, which in turn causes overheating and tubing exfoliation.

Ash plugging restricting gas fl ow in a horizontal tube component area. Velocity increases along the path of least resistance, where there is less ash (line).

Slag fence at top of aperture slope causes ash to drop out to bottom of the boiler.

Aperture slope returns ash from upper furnace to boiler bottom.

Economizer outlet, with 90 degree turn and hopper to collect ash, slag and debris.

Hopper bottom directs heavier ash to removal system at bottom of boiler.

Headers

Platent Superheater

Waterwalls

Spiral Clad Tubing (to prevent erosion/ corrosion after low

NOx conversion)

Ash Slope Section

PendentSuperheater

Reheater

Economiser

1

2

3

4

1

2

3

4


Air Heater and Air In-Leakage Our next topic is tramp air: how

an innocent-sounding circumstance such as a little bit of air in-leakage can infl uence MACT pollutants.

Th e average age of coal fi red boilers in America is nearly 40 years. As boilers age, and joints, weld seams, boiler tube membranes, convection pass tube penetrations and expansion joint cracks open up, the result is excess outside air getting drawn into what we call the boiler setting. Th is is “tramp air” or “air in-leakage.”

Air that leaks into a furnace bottom, ash hopper water-seal, or through a penthouse or convection pass, does nothing for combustion. But this air in-leakage is sensed by the oxygen analyzers at the economizer exit and it is treated by the combustion controls as “combustion air.”

Th e excess air that leaks into a suction fi red boiler is measured by an oxygen analyzer, just the same as air that was admitted through the windbox. Th is is an industry-wide problem and is very much under-appreciated. Air in-leakage can result in heat rate penalties on the magnitude of 300 BTUs per kilowatt hour.

Th is can be quantifi ed by oxygen rise measurements using water cooled HVT probes in the furnace, combined with air heater fl ue gas inlet and fl ue gas outlet traverses for a traditional air heater leakage test. Checking the oxygen rise from the furnace to the stack is useful. For a new boiler in operation and at normal excess air levels, the stack excess oxygen may be as low as fi ve percent. Often we test as much as 15 percent excess oxygen. Th is is a lot of air in-leakage and it is very costly from fan power standpoint alone. It is even worse when the heat losses are calculated.

Air-in leakage at the air heater is another factor. Regenerative Lungstrom air heaters should be capable of nine percent or lower leakage rates. Leakage rates higher than nine percent negatively

Figure 12: Sources of Air In-Leakage

Lower Furnace / Water Seal....5%

Furnace................................... 1-2%

Penthouse............................... 5-10%

Convection Pass andEconomizer Hopper................ 5-10%

Flue Gas Duct......................... 0-3%

Air Heaters.............................. 15-20+%

1

2

3

4

5

6

Normal location of the permanent oxygen analyzers for boiler O2 trim.

1

2

3

4

5

6


aff ect boiler effi ciency in two main ways. First, excessive auxiliary power for fans is required to move the extra airfl ow. Second, the heat rejection of the fl ue gas is greater because wasted heat requires operators to maintain the air heater’s “cold end temperature.”

Greater leakage rates mean more heat needs to be applied to the air entering to keep the cold end baskets above the acid dew-point. When the boiler effi ciency is calculated with a “corrected to no-leakage”fl ue gas exit temperature, the corrected temperature will be signifi cantly higher when the dilution is accounted for. For example, if the corrected-to “No-Leakage” temperature is 35˚ above normal or design, then this represents about one full percentage point in effi ciency penalty.

Air in-leakage is just one part of a holistic focus on compliance. Taking this approach uncovers unseen opportunities, which often translate to basic process adjustments—saving lots of money on downstream equipment investments.

We have seen people spend hundreds of millions of dollars for scrubbers and SCRs and back-end equipment, and walk right past expansion joints, casing tears on the furnace, pulverizer re-builds, fuel fi neness analysis, and tramp air in-leakage as high as 25 percent. Th ere are a lot of opportunities being missed.

Figure 13: Optimizing Combustion - Ideal Test Locations

Figure 14: Air In-Leakage and the Airheater.

HVT test locations to evaluate the fl ue gas chemistry

Maintain optimum coal sizing at yard crusher

Gravimetric load cell feeder for limestone and coal feed

Secondary airfl ow measuring devices

Field calibrate airfl ow monitoring devices

Primary airfl owmeasuring devices

Test ports at economizer and APH outlets to test airheater performance and check for tramp air

Multipoint samplers at economizer outlet

Bypass seal: leakage passing around the APH into the warm air fl ow

Bypass seal: leakage passing the axial seals into the gas fl ow

Bypass seal: leakage passing around the APH into the cold gas fl ow

Hot radial seal leakage

Cold radial seal leakage

GAS side

AIR side


Process Conditions and Emissions Improving a boiler’s thermal effi ciency and airheater performance, and reducing air in-leakage,

are important aspects of whole-plant optimization and regulatory compliance planning. Th ese factors can contribute signifi cantly to the volume and temperature of fl ue gas treated by environmental equipment. In this section we discuss in more detail specifi c process improvements and their eff ects on emissions.

First, consider thermal effi ciency or unit heat rate. Th e red line in Figure 15 shows a case where the unit heat rate is reduced from 11,500 to 10,500, thereby reducing treated gas volume by 8.7 percent. Correlating the eff ects of this effi ciency improvement to ESP performance, we see that the result is a 26 percent reduction in outlet emissions. (Blue line in Figure 15.)

Next, let us look at air in-leakage. Th e dark red line in Figure 16 shows a case where reducing the stack O2 concentration from 7.5 percent to 6 percent reduces the treated gas volume by 9.5 percent. Th is can produce a 22 percent reduction in outlet emissions. (Orange line in Figure 16.)

Finally, let us take fl ue gas temperature into account. Th e red line in Figure 17 shows a case where the fl ue gas temperature is reduced from 350˚ to 280,̊ and the gas volume is reduced by about 8.6 percent. In this case, since fl ue gas temperature is also critical to ash resistivity, the ESP performance is improved through two methods. Th e result is that the outlet emissions are reduced by over 36 percent. (Green line in Figure 17.) It is also important to note that any reduction in gas volume should also reduce the quantity of sorbent feed-rates.

Figure 17: Reducing Flue Gas Temperature

Figure 15: Improving Unit Heat Rate

Figure 16: Reducing Air In-Leakage

36.78%

8.64%

0%

5%

10%

15%

20%

25%

30%

35%

40%

270 280 290 300 310 320 330 340 350 360

Flue Gas Temperature (F)

Reduction in Outlet Emissions (%)

Reduction in Gas Volume (%)

22.02%

9.56%

0%

5%

10%

15%

20%

25%

30%

35%

40%

5.75 6.00 6.25 6.50 6.75 7.00 7.25 7.50 7.75

Flue Gas Oxygen (F)



26.22%

8.70%

0%

5%

10%

15%

20%

25%

30%

35%

40%



Heat Rate (Btu/kW-hr)

10,300 10,500 10,700 10,900 11,100 11,300 11,500 11,700


Pollutant Capture Finally, we move downstream to

the back end of the plant to look at eff ective ways of reacting to particulate matter, mercury, D&Fs, CO and HCl to prevent these pollutants from exiting the stack.

In this section, we look at a case study that illustrates what can happen on the back end and what can be done to respond to all the factors discussed so far. Figure 18 displays the current particulate emissions and various improvement options for each of the boilers discussed in the What We’ve Learned About MACT section of this paper (see page 2.)

Our approach is to use experience with various equipment designs and process characteristics to suggest cost eff ective improvements. Th en, we use our precipitator performance model to predict the future emission levels that would be achieved with each option.

Some of the options are strictly related to process changes. For example, we know that dioxin and furan levels reduce dramatically if precipitator inlet temperatures are reduced below 350.̊ Th is process change will also reduce particulate emissions by reducing treated gas volume and ash resistivity.

In this case, we predict that reducing inlet temperatures would bring all of the boilers into compliance on particulate, except for Boiler 8. Many other possibilities exist for improving precipitator collection effi ciency. Th ese include optimizing power supplies, making fl ow distribution improvements, and upgrading internal components. With this modeling process we can predict which combination of options provides the best value.

Figure 18: Pollutant Capture Case Study


Once compliance is reached for particulate emissions, we would recommend re-assessing MACT pollutant emissions. If mercury and/or HCl are still an issue, it is probably time to evaluate various sorbent injection systems.

It is worth noting that very similar fuel sources were utilized for all eleven of the boilers in this case study. As we continue the evaluation process, fuel considerations will be one of the fi rst things to look at. If it is possible to get around some of the mercury emissions by changing fuels, and if doing so does not negatively impact the rest of the process, that is a good choice to make. Part of the holistic approach is taking into account fuel options and how they impact combustion, slagging, boiler performance and ESP performance.

Conclusion We all know where we want to get to on MACT, but if we do not know where we are starting

from, it is diffi cult to get there. Our goal is to go after the low-hanging fruit: simple things like removing slag and re-establishing gas lanes so the gases can fl ow through as designed with no restriction, or reducing tramp air in-leakage. Revisiting these factors in the process of inspections, repairs and re-alignment does not require a lot of capital money.

Th e good news is, by starting with baseline testing and optimizing inputs, you may very well fi nd out that little or no investment is required on the back end as far as new equipment. Th ere is a good chance compliance is within reach simply by optimizing what you already have.

Comments

We invite you to share your thoughts about boiler MACT in general and this guide in particular. Please send comments to Mae Kowalke, [email protected].

4590 Hamann ParkwayWilloughby, OH 44094(440) 942-8990Fax: (440) 942-6824

www.neundorfer.com

© Neundorfer, Inc. Information is subject to change without notice and without liability therefor. Trademarks used herein are property of their respective owners.

About the Authors

Steve Ostanek, Neundorfer’s President, joined the company in 1982 and has contributed to its performance in many ways including customer relations, process and equipment analysis, training, consulting, strategic planning and personnel development. He works with the Neundorfer team and with customers to identify opportunities for increasing energy effi ciency and reducing air pollution. Steve holds a Bachelor of Science in international marketing from the University of Akron.

Jeremy Timmons, Chemical Engineer, joined Neundorfer, Inc., in 1999 and spends most of his time developing eff ective approaches to performance-related ineffi ciencies with air pollution control systems. His specialties include computational fl uid dynamics (CFD), physical fl ow modeling, and fl ue gas conditioning systems. What he enjoys most is working on research and development projects, focusing on helping customers address long-range planning. Jeremy holds a Bachelor of Science in chemical engineering from Ohio University.

Richard Storm is CEO and Senior Consultant at Storm Technologies, Inc., and has more than 40 years experience fi ne-turning coal-fi red boilers to achieve lowest possible NOx, best effi ciency and maximum fuel fl exibility. He founded Storm Technologies in 1992 to focus on helping improve the effi ciency of America’s coal utility fl eet. Richard has authored dozens of technical papers and presented numerous workshops and seminars. He holds a Power Plant Operation degree from Williamson School of Mechanical Trades and is a member of American Society of Mechanical Engineers, National Society of Professional Engineers, American Coal Council, and ASTM International.

John Cavote, expert boiler inspector and instructor, founded United Dynamics Corporation in 1979. He has performed more than 1,000 inspections of utility boilers in his 35-plus years in the industry. John followed in the footsteps of his grandfather and father, benefi ting from generational experience handed down consecutively from father to son. His instruction to thousands has advanced the quality of boiler inspections worldwide. John is the author of more than 10 training manuals and holds licenses and certifi cates in the repair of pressure parts. He is recognized as one of the world’s foremost experts on techniques and methodology for boiler inspection.

Mae Kowalke, Manager of Stories for Neundorfer, Inc. joined the company in 2009 and has more than 10 years experience in journalism, marketing and communications. At Neundorfer, she supports customer service and company growth by making connections between information, ideas and opportunities using the communications power of stories. Mae holds a B.A. in Communications from Th omas Edison State College.

boiler mact compliance - neundorfer

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